Showing papers on "Petroleum reservoir published in 2019"

The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone

Abstract: Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.

Charging of Carboniferous volcanic reservoirs in the eastern Chepaizi uplift, Junggar Basin (northwestern China) constrained by oil geochemistry and fluid inclusion

Abstract: Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (Th) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range Th distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C20 + C21 triaromatic steroids/C20 + C21 + C26–C28 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.

Smart water flooding performance in carbonate reservoirs: an experimental approach for tertiary oil recovery

Abstract: Smart water flooding as a developing technique utilizes modified water chemistry in terms of salinity and composition to prepare the best-suited brine composition for a specific brine/oil/rock system to obtain higher oil recovery efficiency. Huge amount of unrecovered oil is expected to be remained in carbonate reservoirs; however, few research works on incremental oil recovery during smart water injection in carbonate cores at reservoir condition are reported. Several core flooding tests using one of the Iranian carbonate reservoir rock are conducted to check the effectiveness of smart water injection for more oil recovery efficiency. The results reaffirm the positive effect of sulfate ions to play a key role for better smart water performance. Moreover, it was concluded that the calcium ion concentration is not as effective as magnesium ion for the tests performed at reservoir condition. Synthetic sea water (high-salinity) flooding was considered as the base scenario which results in almost 63% oil recovery efficiency for secondary recovery scenario. Formation of micro-emulsions was found to be the main reason of additional pressure drop during low-salinity water flooding. This clearly showed that the diluted smart water injecting increases the ultimate oil recovery up to 4–12% for already water-flooded carbonate reservoirs.

Capillary-based method for rock typing in transition zone of carbonate reservoirs

Abstract: Reservoir simulation is established as a good practice to make the best decision for a petroleum reservoir. The reservoir is characterized in terms of reservoir elements such as structural model, well data, rock and fluid properties. Then the reservoir model is enhanced through history matching and finally different prediction scenarios are tried to find the best plan for the reservoir understudy. The more accurate the reservoir is characterized, the faster and the more precisely the history match is finished and the more reliable predictions are obtained. The most important part of reservoir characterization is the rock typing, where the quality of CCAL (conventional core analysis) and SCAL (special core analysis) properties are evaluated and estimated for any simulation grid. The resulting oil in place must be confirmed by the OOIP (original oil in place) calculated based on average petro-physical parameters for any layer. To allocate different rock types to simulation grid, rock types should be assigned according to different ranges of rock differentiation parameter which has to be determined in any specific study. Based on our experience in Iranian carbonate reservoirs, most frequently irreducible water saturation is the rock differentiation parameter. In the oil zone, water saturation from log data is assumed to be the irreducible water saturation. Thus, the rock type is identified with no trouble. The problem arises in transition zone, where water saturation from log data is not equal to the irreducible water saturation of that rock. This study includes the observed variations in terms of water saturation data versus depth and how to assign rock types to the transition zone grids. The objective of the capillary-based method is to produce a water saturation map which honors laboratory data as well as the well log data and considers the depth so that it can handle the transition zone in a proper manner. In fact, novelty of this work is to explain how it is possible to consider log and capillary pressure data together so that the most accurate rock type is assigned to reservoir grids of the transition zone. Moreover, this method is consistent with equilibration method for initializing reservoir simulations. A procedure is presented for how to implement the capillary-based method in a stepwise manner. Once the proposed method is carried out, the initialized simulation model is consistent with all sources of data (core analysis and petro-physical data). In this procedure original oil in place calculated after the initialization for simulation is more accurate and can be cross-checked with volumetric calculation based on interpreted log data. Therefore, it is considered to facilitate subsequent stages of reservoir study, namely history match and prediction.

The scientific connotation of oil and gas formations under deep fluids and organic-inorganic interaction

Abstract: As a relatively stable craton block in the earth system, the petroliferous basin is influenced by the evolution of the earth system from the early development environment of source rocks, hydrocarbon formation, and reservoir dissolution to hydrocarbon accumulation or destruction. As a link between the internal and external factors of the basin, deep fluids run through the whole process of hydrocarbon formation and accumulation through organic-inorganic interaction. The nutrients carried by deep fluids promote the bloom of hydrocarbon-generating organisms and extra addition of carbon and hydrogen source, which are beneficial to the development of high-quality source rock and enhancement of the hydrocarbon generation potential. The energy carried by the deep fluid promotes the early maturation of the source rock and facilitates the hydrocarbon generation by activation and hydrogenation in high-mature hydrocarbon sources. The dissolution alteration of carbonate rocks and clastic reservoirs by CO2-rich deep fluids improves the deep reservoir space, thus extending the oil and gas reservoir space into greater depth. The extraction of deeply retained crude oil by deep supercritical CO2 and the displacement of CH4 in shale have both improved the hydrocarbon fluidity in deep and tight reservoirs. Simultaneously, the energy and material carried by deep fluids (C, H, and catalytic substances) not only induce inorganic CH4 formation by Fischer-Tropsch (F-T) synthesis and “hydrothermal petroleum” generation from organic matter by thermal activity but also cause the hydrothermal alteration of crude oil from organic sources. Therefore, from the perspective of the interaction of the earth’s sphere, deep fluids not only input a significant amount of exogenous C and H into sedimentary basins but also improve the reservoir space for oil and gas, as well as their enrichment and accumulation efficiencies.

Petroleum systems framework of significant new oil discoveries in a giant Cretaceous (Aptian–Cenomanian) clinothem in Arctic Alaska

Abstract: Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km2 (10,000 mi2). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.

New directions in an established gas play: Promising dolomite reservoirs in the Middle Triassic Leikoupo Formation of the Sichuan Basin, China

Abstract: The discovery of carbonate gas fields in the Middle Triassic Leikoupo Formation of the Sichuan Basin has a complex history. In recent years, a series of structural fields have been discovered in the western Sichuan Basin. Their discovery confirms the immense exploration potential of the Leikoupo Formation. In this study, we analyze the characteristics of Leikoupo Formation exploration plays using exploration wells and test data, aiming to provide a reference for further discoveries. The Leikoupo Formation represents the uppermost unit in the Sichuan marine carbonate platform succession. During its deposition, the whole basin was characterized by a restricted and evaporitic platform. Two classes of reservoirs developed. One is pore–fracture reservoirs, in marginal platform and intraplatform shoals, and another is fracture–vug reservoirs in the karstic weathering crust of the formation-capping unconformity. Three hydrocarbon accumulation models were established for the Leikoupo Formation based on the spatial and temporal relationship among the source, reservoir, and cap rocks. Two types of exploration plays are present in the Leikoupo Formation, that is, shoal (including intraplatform shoal and marginal platform shoal) dolomite plays and karstic dolomite weathering crust plays (including intraplatform shoal karst and marginal platform shoal karst). The western Sichuan depression in the karstic slope belt presents immense exploration potential because of a proximal hydrocarbon supply, charging via an extensive fracture network, shoals and karstic reservoir, a good seal rock of terrestrial mudstone, and potential composite hydrocarbon accumulations in stratigraphic traps, making it a promising area for future exploration.

Systematic Investigation of Asphaltene Deposition in the Wellbore and Near-Wellbore Region of a Deepwater Oil Reservoir Under Gas Injection. Part 1: Thermodynamic Modeling of the Phase Behavior of Polydisperse Asphaltenes

Abstract: Thermodynamic modeling is conducted for a high-asphaltene, high-resin crude oil produced from a deepwater reservoir using the perturbed-chain statistical associating fluid theory (PC-SAFT). The asp...

Mechanical earth modeling and fault reactivation analysis for CO2-enhanced oil recovery in Gachsaran oil field, south-west of Iran

Abstract: There is a huge potential for CO2-EOR and CO2 storage in depleted carbonate reservoirs in the south-west of Iran. In the first step of a CO2-EOR operation, a geomechanical assessment is needed to find out geological conditions, mechanical and strength properties of formation rocks (e.g., reservoir rock and caprock), in situ stress magnitudes and orientation and in situ pore pressure profile. An integrated analysis is performed in this work for geomechanical assessment of a reservoir–caprock system in Gachsaran oil field, south-west of Iran. A one-dimensional mechanical earth model (MEM) is built for 47 wells in the studied field based on drilling and logging data, laboratory and in situ tests. Static elastic and strength parameters of various formation rocks (limestone, dolomite, anhydrite, gray marl and salt) are evaluated from laboratory experiments. Empirical correlations are obtained to convert dynamic rock properties and well-log data to static elastic properties and strength parameters. The initial in situ pore pressure is calculated using modified Eaton method. In situ stresses state is evaluated based on the poroelastic method and calibrated using LOT and XLOT tests. The orientation of in situ stresses is obtained based on image logs. Fractures and faults analysis is performed to determine their orientations. An analytical analysis is performed to estimate the maximum sustainable CO2 injection pressure to prevent fault reactivation. This study presents a comprehensive method to reservoir and caprock characterization using laboratory and well-log data and 1D mechanical earth model. It helps the analysis of the geomechanical problems during CO2-EOR and provides the necessary information to build 3D geomechanical model for numerical simulations.

Integrated Seismic Interpretation, 2D Modeling along with Petrophysical and Seismic Attribute Analysis to Decipher the Hydrocarbon Potential of Missakeswal Area, Pakistan

Abstract: Missakeswal is an important hydrocarbon field, lying on active foreland fold and thrust belt of Himalayan orogeny in Potwar plateau. Integrated study of 2D seismic data (SEG-Y, Navigation and seismic velocities) and well logs helps us to delineate the potential reservoir rock of the area. Seismic interpretation based on stratigraphic studies and well tops, aids to mark four reflectors; Chorgali, Sakesar, Lockhart and Basement. Time sections are converted to depth section using velocity analysis system to delineate subsurface structure. Besides this, fault-bounded anticlines and crustal shortening analysis of the depth sections, revealed that folding in the sedimentary successions pre-date reverse faulting and regime of the Potwar basin, is suitable for hydrocarbon accumulation. 2D modeling of the interpreted seismic sections confirms reverse faulting in the sedimentary successions and normal faulting in the basement. Moreover, Seismic Attributes Analysis has carried out which helps in understanding the lateral continuity, bedding sequences and thickness of desired beds highlighted the petroleum system and affirmed the interpretation. The identified structural variations would help in the understanding of the regional tectonic settings, besides this, reservoir character in terms of lateral thickness variation, fault offsets and lithological dissimilarities are achieved. It also reveals that carbonate successions of the Sakesar and Chorgali formations acted as potential reservoirs in Missakeswal area.

Permeability prediction from wireline logging and core data: a case study from Assam-Arakan basin

Abstract: Permeability is an important petrophysical parameter of hydrocarbon reservoirs for oil and gas production. Formation permeability is often measured in the laboratory test using core samples. However, when few core samples are available to calculate the permeability in the field, estimation of permeability becomes a challenging task. In study area, the Chandmari field of upper Assam-Arakan basin with the availability of only seven core samples and conventional logs such as density, porosity, resistivity and gamma ray data from few wells, the estimation of permeability becomes a difficult task. Therefore, in the present study an attempt is made to estimate the permeability from well log and core data using Buckles’ method approach in Langpar and Lakadong + Therria sanstone reservoir of Eocene–Paleocene geologic age in the field under the assumption and geological support that reservoirs in the study area are clean sand having very less shale control and are homogenous reservoir with little/no heterogeneity. In this study, petrophysical evaluation from log data and that from core data are integrated for the analysis of the reservoir characteristics. The relationship between porosity and water saturation which is required to distinguish mobile from capillary bound water or irreducible water saturation is used to estimate the irreducible water saturation. The estimated irreducible water saturation which is an essential parameter for water cut and permeability estimation is used for estimating the permeability in the field. The estimated permeability in the reservoirs using Buckles’ method ranging from 1500 to 4554.38 mD is well matched with the permeability estimated from core sample. The estimated permeability results suggest that the oil reservoir has the higher permeability than the gas reservoir. The permeability estimation relationship can further be used for the estimation of permeability in the inter-well region of Chandmari oil field.

A review of producing fields inferred to have upslope stratigraphically trapped turbidite reservoirs: Trapping styles (pure and combined), pinch-out formation, and depositional setting

Abstract: Siliciclastic turbidite systems that pinch out updip toward their proximal margin are prime targets for hydrocarbon exploration, especially in deep-water basins. Such “upslope stratigraphic traps” potentially offer large-volume discoveries but have significant geological risks, notably because of ineffective closure or containment. In the published literature, at least 20 fields from 11 basins globally with 6–7 billion BOE of cumulative discovered reserves have been inferred to be reliant on upslope pinchout traps. These fields are reviewed in terms of their interpreted trapping styles, pinch-out formation process, and depositional-tectonic setting. Reservoirs display a range of upslope trapping styles, including pure (depositional and erosional) stratigraphic pinch-outs and combined stratigraphic-structural traps. In one-third of cases, faulting appears intimately linked to updip trapping, either through offsetting slope feeder conduits or assisting pinch-out development, and in some cases, faulting may be the most important updip trapping element. Sediment bypass and erosion in proximal areas is the most common inferred pinch-out formation mechanism. Some reservoirs also demonstrate the ability of erosional truncation by mud-prone channels and mass transport deposits to form viable stratigraphic traps and seals. Encouragingly for exploration, robust pinchout traps occur in various tectonic settings on a variety of different slope types and positions along the slope profile. Most large-volume discoveries to date, however, are restricted to the toe-of-slope environment in graded passive margins or out-of-grade rift and transform margin settings. Insights into the nature and occurrence of upslope stratigraphic traps are important for future exploration, especially for evaluating new license areas and risking prospects.

Assessing the application of miscible CO2 flooding in oil reservoirs: a case study from Pakistan

Abstract: Miscible carbon dioxide (CO2) flooding has been recognized as a promising approach to enhance the recovery of oil reservoirs. However, depending on the injection strategy and rock/fluid characteristics, efficiency of the miscible CO2 flooding varies from reservoir to reservoir. Although, many studies have been carried out to evaluate the performance of the miscible CO2 flooding, a specific strategy which can be strictly followed for a hydrocarbon reservoir has not been established yet. The aim of this study is to assess one of Pakistan’s oil reservoirs for miscible CO2 flooding by applying a modified screening criterion and numerical modeling. As such, the most recent miscible CO2 screening criteria were modified, and a numerical modeling was applied on the prospective reservoir. Based on the results obtained, South oil reservoir (S3) is chosen for a detailed assessment of miscible CO2 flooding. It was also found that implementation of CO2 water-alternating gas (CO2-WAG) injection at early stages of production can increase the production life of the reservoir.

Reservoir rock typing and zonation in sequence stratigraphic framework of the Cretaceous Dariyan Formation, Persian Gulf

Abstract: This study delineates reservoir and non-reservoir zones in the Lower Cretaceous Dariyan Formation as units that are characteristic of the stratigraphic section representative of portions of the Persian Gulf offshore area. Reservoir rock types are categorized by textural and diagenetic properties. Static flow zones were delineated by porosity and permeability measurements of cored intervals. Electrofacies were prepared from clusters of petrophysical data to define reservoir zones for areas lacking wells with cored intervals. The attributes of these reservoirs are integrated into a sequence stratigraphic framework. This research indicates that rock types and reservoir zones of the Dariyan Formation differ in the studied fields located to the west and to the east in the Persian Gulf. These differences are interpreted to have resulted from a differing tectono-stratigraphic framework that controlled depositional facies and subsequent diagenesis. For example, reservoirs associated with the lower and upper carbonate units of the Dariyan Formation have different lithofacies and diagenetic modifications that resulted from deposition at two intrashelf basins at areas to the northwest and to the southeast in the Persian Gulf, and subsequent exposure to meteoric water flows during subaerial exposure.

Determine In-Situ Stress and Characterize Complex Fractures in Naturally Fractured Reservoirs from Diagnostic Fracture Injection Tests

Abstract: Estimation of in-situ stresses has significant applications in earth sciences and subsurface engineering, such as fault zone studies, underground CO2 sequestration, nuclear waste repositories, oil and gas reservoir development, and geothermal energy exploitation. Over the past few decades, Diagnostic Fracture Injection Tests (DFIT), which have also been referred to as Injection-Falloff Tests, Fracture Calibration Tests, and Mini-Frac Tests, have evolved into a commonly used and reliable technique to obtain in-situ stress. Simplifying assumptions used in traditional methods often lead to inaccurate estimation of the in-situ stress, even for a planar fracture geometry. When a DFIT is conducted in naturally fractured reservoirs, the stimulated natural fractures can either alter the effective reservoir permeability within the distance of investigation or interact with the hydraulic fracture to form a complex fracture geometry, this further complicates stress estimation. In this study, we present a new pressure transient model for DFIT analysis in naturally fractured reservoirs. By analyzing synthetic, laboratory and field cases, we found that fracture complexity and permeability evolution can be detected from DFIT data. Most importantly, it is shown that using established methods to pick minimum in-situ stress often lead to over or underestimates, regardless of whether the reservoir is heavily fractured or sparsely fractured. Our proposed “variable compliance method” gives a much more accurate and reliable estimation of in-situ stress in both homogenous and naturally fractured reservoirs. By combining the unique pressure signatures associated with the closure of natural fractures, a lower bound on the horizontal stress anisotropy can be estimated.

Diagenesis and its influence on reservoir quality and oil-water relative permeability: A case study in the Yanchang Formation Chang 8 tight sandstone oil reservoir, Ordos Basin, China

Abstract: Abstract Different from conventional reservoirs, unconventional tight sand oil reservoirs are characterized by low or ultra-low porosity and permeability, small pore-throat size, complex pore structure and strong heterogeneity. For the continuous exploration and enhancement of oil recovery from tight oil, further analysis of the origins of the different reservoir qualities is required. The Upper Triassic Chang 8 sandstone of the Yanchang Formation from the Maling Oilfield is one of the major tight oil bearing reservoirs in the Ordos Basin. Practical exploration demonstrates that this formation is a typical tight sandstone reservoir. Samples taken from the oil layer were divided into 6 diagenetic facies based on porosity, permeability and the diagenesis characteristics identified through thin section and scanning electron microscopy. To compare pore structure and their seepage property, a high pressure mercury intrusion experiments (HPMI), nuclear magnetic resonance (NMR), andwater-oil relative permeability test were performed on the three main facies developed in reservoir. The reservoir quality and seepage property are largely controlled by diagenesis. Intense compaction leads to a dominant loss of porosity in all sandstones, while different degrees of intensity of carbonate cementation and dissolution promote the differentiation of reservoir quality. The complex pore structure formed after diagenesis determines the seepage characteristics, while cementation of chlorite and illite reduce the effective pore radius, limit fluid mobility, and lead to a serious reduction of reservoir permeability.